Tim Bradner

Flint Hills to close another crude oil refining unit

Flint Hills Resources announced April 10 it is closing its No. 1 crude oil refining unit at the company’s refinery at North Pole due to challenging economic conditions faced by the refinery, company officials said in a press release. The company will be required to cut 35 to 40 jobs, officials said. “This is the most difficult decision we have had to make in operating this refinery,” Mike Brose, vice president of Alaska operations and manager of the Flint Hills refinery, said in a statement. “We value our employees very much; they are all dedicated professionals who have worked very hard to help us compete in what is an extremely difficult economic climate.”     The refinery has the capacity to process 220,000 barrels per day of crude oil taken from the Trans-Alaska Pipeline System. It extracts a portion of the crude barrel to make jet fuel, diesel, some gasoline and naphtha. The amount of product produced has varied but it has been about 60,000 barrels per day in the past when all three crude oil refining units were operating. Flint Hills will continue operating its remaining No. 2 crude unit to produce jet fuel, gasoline, asphalt and some specialty fuels for Alaska markets while continuing to meet all its contractual commitments, Flint Hills said in its statement. The refinery previously idled its No. 3 crude unit, which produced mainly jet fuel. Flint Hills said the current economics of refining is challenging for refineries across the world. Over the last several years 16 refineries in North America and Europe have shut down. Because of the isolated location of the Flint Hills Resources Refinery and the dependence on one source of crude oil, the North Slope, Flint Hills faces greater economic challenges than many other refineries.  “The North Pole refinery was designed to use crude oil as a source of energy to power operations, which is a considerable disadvantage,” Brose said. “Crude oil prices and Alaska North Slope Crude prices in particular are very high and are expected to remain that way for the foreseeable future. In addition, the calculations associated with the Quality Bank place our refinery in a disadvantaged position. We need to solve these two problems in order to survive, and a single crude unit configuration gives us the best platform to work on these problems.” The Quality Bank is an adjustment mechanism for crude oil shippers in the TAPS pipeline. Flint Hills pays a fee to the Quality Bank to compensate other shippers for the effects on the crude oil quality of the refinery’s return of unused portions of crude oil to the pipeline.  The affected employees will have an opportunity to apply for other positions within the company. Employees who do not receive other positions in the company will receive severance packages. Flint Hills Resources will also provide placement support for employees seeking job opportunities outside the company. Another problem the refinery faces is that it must burn crude oil to provide energy, which is very costly at current crude prices. Flint Hills is now in a joint study with Golden Valley Electric Association, the regional electric cooperative, of a possible plan to truck liquefied natural gas from the North Slope, to provide energy to the refinery and reduce the need to use expensive crude oil as fuel. A decision on this is expected at the end of this year, Golden Valley President Brian Newton has said. It would take two to three years to build the LNG plant at Prudhoe Bay and the regasification and tanks at the refinery, however. The state Legislature is considering a set of tax credits that would assist in the development of community LNG storage tanks such as those that could serve Golden Valley and the refinery.

Legislators rush to resolve key bills

With about a week left in the 2012 state legislative session, bills are piled up in the Finance committees of both the state House and Senate and, typically, the most pressing business is left to the last minute. As is customary, some bills that are priorities of leaders in the House and Senate are being held “hostage” in the other body to gain negotiating leverage. For example, the House has Sen. Johnny Ellis’ bill extending the state film tax credit in its Finance Committee, where lengthy hearings are being held in a subcommittee. The bill passed the Senate last year. Similarly, the Senate has House Speaker Mike Chenault’s bill to expand powers of the Alaska Gasline Development Corp., a state corporation planning an in-state gas pipeline, on a slow track. That bill passed the House March 27 but was assigned to three committees in the Senate. A hearing in the first committee, the Senate Community and Regional Affairs Committee, was set for April 3 but was cancelled. The Senate Finance Committee hopes to finish work, at last, on its version of an oil tax reform bill the weekend of April 7 and 8, but there seems little prospect that the House will be able to give the bill adequate review before the adjournment deadline at midnight, April 15. House Speaker Chenault expressed that view in a briefing April 2. The Senate bill is very different than the oil tax bill passed by the House last year but House leaders said the form of the bill isn’t as important as whether the Senate bill would reduce taxes sufficiently to encourage investment. There’s talk that the Legislature may go into overtime to complete work on the oil tax, but that’s speculation at this point. Meanwhile, another important bill, the state capital budget — which pays for construction work — is due to emerge from behind closed doors soon, according to Sen. Bert Stedman, R-Sitka, co-chair of the Senate Finance Committee. Unlike the oil tax, there likely will be a rough consensus already in place between the House and Senate on the capital budget before it appears to the general public.   In a March 2 briefing by Senate leaders, Stedman said informal talks are being held with House leaders on the capital budget bill. The House Finance Committee, meanwhile, has been holding hearings and working on its approach to the capital budget, but will wait, as is the custom, to work on the Senate bill when it comes over from that body. The normal legislative procedures will take place with the capital budget once it surfaces, with hearings held in the Finance committees. The Legislature’s tradition, however, is that the key decisions are made in private and these late-session hearings are largely a formality, mainly a forum for advocates to make last-minute pitches for projects or programs that have been left unfunded in the capital budget. If there are big differences between the House and Senate over projects to be funded, and this isn’t yet known, the capital budget could go to a conference committee. There’s always a chance that could happen, but with time so short, Stedman and his House capital budget counterpart, Rep. Bill Stoltze, R-Chugiak, will likely try to resolve differences informally to speed things along. Stedman said there is an agreement with Gov. Sean Parnell — who can veto line items from the budget bill — for spending not to exceed about $2.9 billion, including federal funds, an amount roughly similar to what legislators approved last year in the capital budget. The senator also said there is agreement not to exceed $450 million on a port projects general obligation bond package that would appear on the state general election ballot in November. If approved by voters, the bonds would fund a variety of port projects around the state, including more work on the Port of Anchorage expansion. The port bonds authorization bill is still being worked on. Operating budget The operating budget bill is moving along smartly. The House has passed its version of the bill and the Senate approved its version April 4, which is close to the House plan that passed March 15. With this bill, which funds state agency operations, a conference committee is customary to work out differences between the bills, which appear to be relatively minor this year, said Sen. Lyman Hoffman, D-Bethel, the Senate Finance co-chair in charge of the operating budget. One difference is that the Senate is proposing $12 million for state funding for tourism promotion while the House has proposed $16 million, Hoffman said. This shouldn’t be difficult to resolve, the senator said. The Senate version of the operating budget is $22 million below Parnell’s proposal for operations spending, Hoffman said, but the bill assumes status quo in school funding, an issue yet to be resolved. Overall, the Senate has held agency operating increases to about 3.6 percent, compared to the 7 percent annual agency spending growth in recent years, Hoffman said. The governor’s proposed operating budget is about $8.86 billion, including federal funds and agency increases similar to those allowed in the Senate version of the bill. If the House agrees to increased funding for education in some form, it would add to the total in the operating budget. School, retirement funding On the school funding proposals, the House Finance Committee is still working on bills passed by the Senate that would grant a three-year, $33 million annual increase in the Base Student Allocation, a formula under which state funds are distributed to school districts. School districts around the state are pushing hard for increases in the BSA to offset inflation and higher fuel costs. House leaders are sympathetic but may want to provide targeted funding, one year at a time, rather than put an increase into the formula itself. The final form of a House proposal on school funding has yet to emerge and this will be another critical end-of-session issue to be resolved. Hoffman said the Senate operating budget also includes special appropriations to state pension funds to deal with the estimated $11 billion-plus unfunded liability for pensions to current and future public employee retirees. So far the bill provides a $500 million appropriation to the Public Employee Retirement System, or PERS, for state and municipal workers, and $500 million for the Teacher Retirement Program, or TRS, for teachers and school district workers, Hoffman said. “These are significant amounts but they are not enough to address the problem,” of the unfunded liability, he said. These amounts are likely to be increased before adjournment. There is hallway talk of the PRS appropriation being increased to $2 billion and the TRS funding to $1 billion, Hoffman said. After all the budget work is done, there is still likely to be a healthy surplus in the state treasury, both from the current fiscal year 2012 budget, which ends June 30, and projected for next year. Some of this is likely to be appropriated to the two state pension funds to deal with unfunded liability and the remainder will likely be deposited in the two state reserve accounts, the Constitutional Budget Reserve and the Statutory Budget Reserve. These funds already hold about $12 billion in liquid assets, and deposits of fiscal 2012 and 2013 surpluses would add to the reserves.

Slope producers align on LNG project

Gov. Sean Parnell announced Friday that the long-running Point Thomson litigation has been settled in an agreement featuring ironclad production requirements with North Slope producers, who also told the governor they have reached alignment on pursuing a major liquid natural gas pipeline to facilitate exports from Southcentral Alaska. “The news keeps getting better for our state,” Parnell said at a press conference at his Anchorage office. “We’re assuring significant new investment at the field, hydrocarbons into (Trans-Alaska Pipeline System) and a timetable for full-field development.” Under the settlement, the companies must be producing gas liquids from Point Thomson by the winter of 2015-16 or significant acreage at the field will automatically return to the state. The objective is to reach 10,000 barrels per day in production, Department of Natural Resources Commissioner Dan Sullivan said. The settlement also requires major infrastructure investment, most notably in a 70,000-barrel capacity “common carrier” pipeline from Point Thomson to TAPS that Sullivan said would utilize the economies of scale and open up the Eastern Slope for production. “The primary goal was to end the warehousing at Point Thomson of Alaska’s fields and get near-term commitments for production,” Sullivan said. “They must lay out a path for full production and the settlement incentivizes progress toward North Slope gas development.” Settlement of the Point Thomson litigation, which affects the 8 trillion cubic feet of gas and 200 million barrels of liquid condensates in that field, was necessary before any large gas project moves forward. Point Thomson’s reserves constitute almost one-fourth of the 35 trillion cubic feet of gas reserves identified on the Slope that could underpin a large gas project. The litigation, which has been under way for seven years and spanned three administrations, revolved around the state’s claims that major Point Thomson leaseowners ExxonMobil, BP and ConocoPhillips and Chevron did not perform on development obligations under the leases. The state had moved to void the leases. “This is clearly a win for Alaskans,” Parnell said. “Alaskans don’t win when their resources are tied up in litigation. This settlement has real work commitments, real production and real consequences.” Parnell shared the letter he received Friday from CEOs Rex Tillerson of ExxonMobil, Jim Mulva of ConocoPhillips and Bob Dudley of BP said the three companies have reached agreement on assessing the LNG export project as an alternative to the pipeline to Alberta called for in the Alaska Gasline Inducement Act, or AGIA. “A southcentral Alaska LNG approach could more closely align with in-state energy demands and needs,” the letter stated. “We are now working together on the gas commercialization project concept selection, which would include an associated timeline and an assessment of major project components including in-state pipeline routes and capacities, global LNG trends and LNG tidewater site locations, among others.” The alignment between ConocoPhillips and BP with ExxonMobil and TransCanada, the latter two companies who have been exploring the Alberta gasline under AGIA, may require a project plan amendment. TransCanada, which had $500 million worth of its expenses covered under AGIA, is currently required to file its export permit with the Federal Energy Regulatory Commission by October. Sullivan said such an amendment to delay that requirement could be done administratively with the approval of him and Department of Revenue Commissioner Bryan Butcher. The Slope companies have additional benchmarks to achieve by the third quarter of this year on the gasline project, and within the settlement is a provision that the producers can earn additional acreage at Point Thomson if they sanction an LNG project between now and 2016. If the producers don’t agree on a gasline concept before then, they will be required to increase liquids production at Point Thomson. “The agreement does not guarantee a major gasline, but moves us a significant step forward,” Sullivan said. Parnell said part of his commitment to the CEOs in exchange for their alignment on commercializing Slope gas through an LNG export project was to address natural gas taxes in the 2013 legislative session. The letter from the CEOs states, “Unprecedented commitments of capital for gas development will require competitive and stable fiscal terms with the State of Alaska first be established.” This would be the fourth time companies have worked on an Alaskan LNG project. The first, in the 1970s by El Paso Natural Gas, was intended to ship LNG to the U.S. West Coast. El Paso did not proceed with the project. The second was an effort by Yukon Pacific Corp., a subsidiary of CSX Corp., in the 1980s to build a gas pipeline parallel to the existing Trans Alaska Pipeline System and an LNG plant at Valdez, the terminus of the TAPS line. Yukon Pacific eventually dropped the project when it could not get commitments of gas supply from producers, the company said. Also in the 1980s the Alaska Natural Gas Transmission System consortium led by Salt Lake City-based Northwest Energy and Foothills Pipe Lines did extensive work on a land pipeline to Alberta following essentially the same route proposed today by Foothills and ExxonMobil. U.S. gas deregulation and the resulting gas supply glut ended the project. Following the demise of ANGTS, a third LNG effort, in the 1990s, was led by two North Slope producers, ARCO Alaska and BP, that also included a Japanese company, Marubeni and Foothills Pipe Lines (now TransCanada) that also would have had the LNG plant at Valdez. This project was dropped when the group concluded the Asia LNG market could not supply large enough quantities of gas, in competition with other suppliers, to make the Alaska project viable. As that project wound down in 1999, the producing companies, this time including ExxonMobil, turned their attention to an overland pipeline. Their work led to the current TransCanada and ExxonMobil overland project, and the competing BP and ConocoPhillips Denali project that those companies dropped in 2011.

Senate works on oil taxes, but clock may run out

The state Senate is continuing its detailed review of state oil and gas taxes, but there are growing worries the clock will run out before any revision of the oil tax can be agreed upon. Lawmakers must adjourn April 15, although there are procedures where the session can be extended. The Senate Finance Committee was expected to have its version of the tax change bill, Senate Bill 192, finished the week of March 26. It is possible that the full Senate could vote on the bill and send it to the House in early April. That leaves about two weeks for the House to consider a complex tax bill that will be different than House Bill 110, which the House approved last year and is now lodged in the Senate. The House-passed bill was originally introduced by Gov. Sean Parnell and is supported by oil and gas companies as making enough changes to stimulate major new investment in the aging North Slope fields. Oil production is now declining at rates of 6 percent or more annually and oil producers and the governor blame the state’s high tax rate as discouraging new investment. In a presentation to the Senate Finance Committee March 21, ConocoPhillips officials said their company’s Alaska capital investments have been flat over the last three years while capital investments in the Lower 48 states have tripled. “With oil prices as high as they are, we ought to be doing a lot more,” Scott Jepsen, ConocoPhillips’ external affairs vice president, told the committee. The problem is the Alaska tax, he said. The company’s Alaska managers can’t get the money because investments in Lower 48 states are more rewarding. Jepsen also told the committee that new investment by the industry would create more revenue for the state. ConocoPhillips’ analyses has shown that every $1 in new investment, the industry has generated $2 in new state tax and royalty income, he said. “Every project is different but over the long run we believe the 2-to-1 ratio has been very consistent,” Jepsen said. It takes time, however, for new projects to be brought on line, and Jepsen said ConocoPhillips is willing to work with legislators to find ways to ease short-term revenue reductions. Another point brought out in the hearings, this one by the Legislature’s own consultants on the tax bill, PFC Energy, is that the current Alaska’s Clear and Equitable Share is clearly discouraging development of new oil production. “ACES appears to work well as a ‘harvest’ (tax) regime. Existing mature fields remain profitable, including capital (investment) needed to achieve a 6 percent decline rate,” Janak Mayer, PFC’s upstream manager, told the Senate Finance Committee March 22. The tax works well for the state, in a harvest mode, in that maximum revenues are extracted from the declining production base, Mayer said. But ACES is not a tax that encourages growth. “ACES inhibits the development of new projects and resources that might help stem or even reverse the decline,” of production, he said. While the state’s net-profits tax was originally intended, when first adopted in 2006, to be “progressive” to help high-cost and technically-challenged oil projects, the effect is actually the reverse, Mayer said. “The high government ‘take’ (in ACES) applies even to very high-cost projects,” and has a detrimental effect on the break-even point at which high-cost projects can be developed, he said. Also, the existing system of capital investment tax credits in the current tax law does not encourage spending on new production but instead encourages the major producing companies to spend money on “renewal” or major maintenance and replacement of production infrastructure, Mayer told the committee. Sen. Lesil McGuire, R-Anchorage, expressed concern in the March 22 hearing as to how the capital tax credits are being used. “I voted for these credits on the understanding that they were for new development. Now I am learning that they are actually being used for renewal,” McGuire said. The credits are the 20 percent investment tax credit the state allows for all oil and gas capital investment. The original intent was that the credits would encourage producers to reinvest profits from Alaska production in the state. Declines and deficits? Meanwhile, the urgency for changing the state tax was highlighted by Damian Bilbao, BP’s head of Alaska finance and developments, when he spoke to the Senate committee March 21. Bilbao pointed out potentially huge deficits in the state budget that could appear if oil production continues to decline at the current 6 percent yearly, and with the state budget continuing to grow. Bilbao showed the committee a chart, using state data, that showed by 2020 oil production would bring in only half enough revenue to fund the state budget. The assumption in the chart, from the state Office of Management and Budget, was for the budget to grow at 4 percent per year. In reality, the budget has been growing at higher rates. It is also likely that the decline in oil production will exceed 6 percent this year and next, industry officials have warned previously. Bilbao said the quickest way to stimulate new production is to stimulate new “in-fill” drilling within the existing fields. The new revenues from added production, which could occur fairly quickly, would help offset any reduction in state income due to a tax reduction. The tax reduction should apply to all production, however, not just new oil produced by the companies, because the base production from the mature, large fields is becoming more challenged by rising costs. Using data given the state revenue department by industry, Bilbao showed overall North Slope per-barrel production costs rising from just under $20 per barrel in 2010 to more than $25 per barrel in 2013. He also expressed concern that PFC Energy, in its modeling work on the economics of a large North Slope producing field, was assuming a “lifting” or production cost of $12 per barrel, about half of what the actual costs are. Finance co-chair Sen. Bert Stedman, R-Sitka, asked Bilbao to work with PFC Energy to do any needed updates to the consulting firm’s modeling. Bilbao said he would do that. The most extended discussion of new oil possibilities came when ConocoPhillips’ Vice President of Finance Bob Heinrich and ConocoPhillips’ Jepsen came before the committee. Jepsen agreed with Bilbao that additional drilling could add new production in mature fields like Kuparuk, which ConocoPhillips operates, “but (under the current tax) when we look at the long-term cash flow and the added investment we just don’t see the upside. We do provide capital to sustain the base production but it’s difficult to get approval to put on another rig or two,” to increase production, he said. Jepsen also said he disagrees with the way the “harvest” term is being used in the discussions. “There are fields in ‘harvest’ mode but these are fields where we see no upside,” or possibility of increased production. “But we are not in harvest mode here, because there are opportunities to grow. If ACES is changed it will change the game,” Jepsen said. Senators were interested in whether ConocoPhillips thinks the Kuparuk field production could be increased above its current 140,000 barrels per day, or even if production could be increased back to 250,000 barrels a day. It would be a challenge, Jepsen said. “We are essentially developing ‘new’ fields inside Kuparuk. These are (small) pools that are only available now because of improvements in technology,” he said. There is a lot of potential with the large West Sak viscous oil resource in the Kuparuk field, but also major technical challenges. “We have about 15,000 barrels a day of viscous production from the core care (of the West Sak) and we may be able to move to the next area of West Sak, but after that it gets really difficult. I can tell you some things we can do to offset decline, and with skill and science maybe we could see some increases,” Jepsen said. The governor’s 1 million barrels-a-day production goal is ambitious, but it’s a good objective. “Even it we achieve part of it we’d be very happy,” he said. To actually achieve it would take moving forward on all fronts, with conventional, viscous, heavy and shale oil. Oil from the offshore will also be important, because while this oil isn’t subject to state taxes it will contribute to state revenues because the larger volume of oil in the trans-Alaska oil pipeline will lower the transportation cost of oil from state-owned lands.  Jepsen urged the Senate committee to be careful in adopting a tax reduction for new oil only. “Keep it simple. If you try to parcel it out, you won’t get there. If you only give incentives to what you produce over the decline curve, you won’t get there,” in achieving new production, he said. “We understand the (short-term) impacts to the treasury,” from a reduced tax. “Maybe there’s some way we can work through this. We won’t see an immediate near-term impact but in the long term there will be a positive impact. It may take five to seven years to get new production on line.” The idea of applying a tax reduction to the entire production is meeting some resistance in the Senate committee, however. “It will just move too much cash across the table,” Stedman said. “This leads us to a more complex discussion, the two-tiered approach. We hear you when you say ‘one size fits all’ but we have to be cautious. There is concern about our making it more complex. It’s complex enough.” As the Senate committee develops its bill the major elements are known: There is agreement that some downward adjustment to the “progressivity” formula in the state production tax is needed. The question is how much the adjustment will be. A minor change in the formula in SB 192 as it emerged from the Senate Resources Committee is considered insufficient to encourage new investment, PFC Energy, the consultants to the Legislature, have told the Senate Finance Committee. Stedman and other members of the committee are very interested in some mechanism that will encourage development of “new” oil through a reduced tax, but also leaving taxes on existing production from older fields without a change. A mechanism fordoing this proposed in the Senate Resources version of SB 192, by raising the “trigger price” at which the progressivity formula kicks in, was judged ineffective by PFC Energy. The Finance committee is now working on alternative ways of accomplishing this.

Mineral exploration spending tops $300 million in 2011

Mining is growing fast in its economic punch in the state, new studies by the industry show. In 2011 the industry employed 4,500 in producing mines exploration, up from 3,500 in 2010 in terms of equivalent full-time jobs, according to studies by McDowell Group, the Juneau-based consulting firm. The average annual pay for a worker in mining reached $100,000 in 2011, up from an average of $95,000 the previous year. State revenues from mining totaled $148 million in 2011, 170 percent up from $58.9 million in 2010, which was also 40 percent up from 2009. Tax payments to local governments, through property taxes or payments-in-lieu of tax, increased from $13 million in 2010 to $17 million in 2011. The research was commissioned by the Alaska Miners Association and the Council of Alaska Producers, two industry associations. Other highlights from the McDowell Group reports: • Exploration spending reached $300 million in 2011, up 13 percent from 2010. • Sixty exploration projects spent more than $100,000 on their prospects in 2011, up from 50 in 2010. Of those explorers, 30 projects spent more than $1 million on their prospects in 2011, up from 24 in 2011. • Including 2011, minerals companies have spent a cumulative $2.8 billion on exploration since 1981. Seven mines were producing in 2011, one more than in 2010. The new producing mine is Nixon Fork, a small underground mine near McGrath, west of Anchorage. Other producing mines include the Usibelli coal mine at Healy, south of Fairbanks; the Fort Knox gold mine northeast of Fairbanks, a surface mine; the Red Dog Mine in the DeLong Mountains north of Kotzebue, a large surface mine; the Pogo Mine, a medium-sized undergroud mine near Delta, east of Fairbanks; and the Kensington and Greens Creek mines near Juneau. Kensington is an underground gold mine at Berner’s Bay, north of the capital city, while Greens Creek in an underground multi-metal mine, mainly zinc and silver, on Admiralty Island west of Juneau. Work was also under way in 2011, as well as in 2010, on a number of medium-to-large size mines still in the advanced exploration phase. These include the large Pebble gold/copper mine near Iliamna southwest of Anchorage; the large Donlin Creek gold mine on the middle Kuskokwim River west of Anchorage; the large-to-medium size Livenood gold project north of Fairbanks; the Niblack multi-metals prospect and the Bokan Mountain rare earths project near Ketchikan in Southeast Alaska; and two coal projects, the large Chuitna coal project at Beluga, on the west side of Cook Inlet, and Wishbone Hill, a medium-size coal project north of Palmer, in the Matanuska-Susitna Borough. In addition to the large producing mines there were about 200 medium and small-sized placer gold mines operating in both 2011 and 2010, the McDowell Group report said.

Study says Inlet gas discoveries won't stop shortage

Despite new natural gas discoveries in Alaska’s Cook Inlet utilities in the region will still experience shortages of gas supply by 2014 due to declining production in maturing fields, according to a new study of Cook Inlet gas reserves and regional demand released Monday. The only practical alternative to deal with the shortfall is the import of liquefied natural gas, said Pete Stokes, commercial manager with Petrotechnical Resources of Alaska, an Anchorage-based consulting firm. PRA’s analysis was done for three Southcentral Alaska utilities, Enstar Natural Gas Co., Chugach Electric Association and Anchorage’s city-owned Municipal Light & Power. “The PRA report just emphasizes what we’re been concerned with for some time, that there is a lot of talk about new gas resources out there but no one is bringing it to market. We need to see results,” said John Sims, spokesman for Enstar Natural Gas Co., the Southcentral regional gas utility. Sims said the three utilities are working on plans to import LNG, but negotiations with potential suppliers are confidential. ConocoPhillips owns and operates a liquefied natural gas plant at Kenai that the company had planned to mothball. However, the plant is now being kept open on a year-by-year basis with incremental shipments being made to customers in Asia. There are reported new discoveries of gas both offshore and onshore in Cook Inlet including from a well drilled last summer by Escopeta Oil Co. from a jack-up rig, but the discoveries have yet to be tested, Stokes said. Even if they can be produced commercially it will take five to six years, or more, to secure permits and build a platform and pipelines and other production facilities. The new gas would not come in time to meet the impending shortfall facing the utilities, he said. The expected supply shortfall that year is 7 billion cubic feet short of the utilities’ projected requirement of 80 billion cubic feet, Stokes said. “Only a significant onshore discovery that is near existing pipelines will be sufficient to offset the shortfall in 2014. Offshore discoveries cannot be developed in time,” he said. There are two new onshore Kenai Peninsula gas discoveries, one by Australia-based independent Buccaneer Energy in a prospect near the City of Kenai and a second in the Kenai National Wildlife Refuge by Alaskan independent NordAq, but both of these require further testing. PRA’s analysis tracks studies done in recent years by the state Department of Natural Resources, which show potential reserve additions in the Cook Inlet Basin sufficient to meet local utility needs to 2020. The difference, Stokes said, is that the state’s study assumes industry will make additional investments by producers in development drilling to prove up needed new reserves. PRA’s study, which is an update of work done in 2009, for the utilities, shows that the investments are not being made, at least at the rate needed. In 2009, PRA estimated that if producers drilled no new development wells utilities would face a shortfall in 2013. The updated analysis just finished shows that some drilling and compression has been added, but that the supply shortfall is pushed out only one year, to 2014. In 2009, PRA estimated that, assuming no discoveries of new fields, 185 new wells need to be drilled in the producing fields by 2020, or 14 to 18 new wells per year, to develop enough new gas to meet local utility demand. That level of drilling would require an investment of $1.9 billion to $2.8 billion, PRA said in its 2009 report. The actual drilling by producers has been far below those levels, Stokes said. In 2010 producers drilled five new production wells. In 2011 six new production wells were drilled. However, the 2011 drilling resulted in far less new production than wells in 2010, an indication of the declining productivity of the large Cook Inlet gas fields. Wells drilled by producers in 2010 averages 18.5 million cubic feet of gas per day additions to production, while the wells drilled in 2011 averaged about 9.9 million cubic feet of gas per day, Stokes said. PRA’s recent analysis indicates that even if producers ramp up drilling by three or four more wells per year the projected shortfall in the utilities’ need still appears in 2014 but drops from 7 billion cubic feet to 1 billion cubic feet that year, Stokes said. Even if drilling is doubled, to six to eight wells per year over the 2010 and 2011 rates, the shortfall is pushed back only one more year, until 2015, he said. The state of Alaska is meanwhile backing a plan to build a 24-inch pipeline to bring gas from the North Slope to Southcentral Alaska, or alternatively a 24-inch “spur line” if a large-diameter pipeline is built to Canada, but gas from the Slope cannot realistically be shipped until 2020 at the earliest, state officials have said. Southcentral Alaska utilities have been grappling for years with the long-term decline of producing fields the region. For many years gas was in surplus to local needs and prices were low, at $1.50 per mcf or lower for many years. There was virtually no exploration given the prices. In recent years prices have increased and are now in the range of $8 per mcf under new gas contracts signed by the utilities, and there has been new exploration in the last two years. Also, the state of Alaska has stepped in with generous incentives for exploration, paying as much as 60 percent to 70 percent of the cost of new wells.

Miners busy with expansions, new projects

From far Southeast Alaska to the far Northwest, minerals companies are busy with projects. Alaska has seven producing mines now, one more than last year. The new producing mine is Nixon Fork on the upper Kuskokwim River, a remote location where fuel and supplies must be flown in. Several new mines may move into production the coming years, all in different parts of the state. Here’s a review of the producing mines and prospects around Alaska: Southeast The new Kensington underground gold mine north of Juneau has completed its first year of production. Coeur d’Alene Mines, the owner, has temporarily cut back production this year so that additional capital improvements can be made, essentially to de-bottleneck of the production process and increase efficiency. When those are completed, gold production will resume according to the company’s plan. At the Greens Creek Mine, on Admiralty Island west of Juneau, owner Hecla Mining is engaged in securing permits for an expansion of the tailings storage facility at the mine. If the plan is approved, Greens Creek will have the capacity to handle tailings for another 30 to 50 years of production. Greens Creek is an underground mine that has been producing a mix of silver, zinc and gold for more than 20 years. Two potential new mines in Southeast are near Ketchikan. One is the Niblack project, a copper-gold-zinc-silver deposit that would be similar to the Greens Creek Mine if brought into production. Niblack Mining Corp. is the developer. The second is Bokan Mountain, a rare earths project that has attracted national attention because it has a type of heavy rare earth mineral that is relatively scarce. Rare earths are a type of mineral used widely in high technology applications including defense technology. The developer at Bokan Mountain is Ucorp, a company that specializes in rare earths projects. Southcentral Two possible coal projects are in the permitting stage. One is the Chuitna project in the Beluga coalfields where the owners, the Bass-Hunt group, are developing a supplemental environmental impact statement. This would be a surface mine that would tap large subbituminous coal resources in the Beluga coal fields. Coal would be mined and moved to coal ships loading at a planned new offshore loading terminal in Upper Cook Inlet with a gondola system. One of the central points of concern at Chuitna is the disruption of several miles of salmon-bearing streams as the coal deposit is mined. The company is working on a mitigation and restoration plan for the salmon streams, but it must have the approval of state agencies. Another potential coal project in Southcentral is Wishbone Hill north of Palmer that is proposed for development by Usibelli Mine Inc., operator and owner of a larger coalmine at Healy. Unlike the Healy subbituminous coal and similar coal at Chuitna, Wishbone Hill has high quality bituminous coal that has attracted the attention of a Japanese company as a customer. Like the present Healy mine and the planned project at Chuitna, Wishbone Hill would be a relatively smaller mine with its coal trucked to facilities where it could be shipped, either to a rail line for shipment to Seward or trucked to the Port Mackenzie dock on Upper Cook Inlet. Interior At Healy, on the Parks Highway about 90 miles south of Fairbanks, Usibelli Mines continues to operate the Usibelli mine that has produced coal for decades. There are substantial untapped coal resources near the mine sufficient to allow the mine to produce for decades more. Usibelli sells to coal-fired power plants in Interior Alaska and also exports coal through Seward to Pacific rim buyers. The company has recently been setting records for coal exports and increased production. Coal is shipped by rail from Healy to Seward, where it is stored and loaded on ships. There are two major producing gold mines in Interior Alaska, the Fort Knox Mine northwest of Fairbanks, a surface mine, and Pogo, an underground gold mine northeast of Delta and east of Fairbanks. Sumitomo Heavy Metals, the owner at Pogo, continues to make incremental capital investments to improve efficiencies at the mine, and has also initiated new exploration nearby in an effort to expand resources and extend Pogo’s operating life. The Fort Knox mine has been in production for some years and is now supplementing its producing and processing of conventional gold ore with a heap leach, a process use to extract gold from low-quality ore. Both Pogo and Fort Knox purchase power through the regional power grid from Golden Valley Electric Association, the Interior electric cooperative, and the large power purchases help stabilize the cost of electricity for residents and businesses in the Fairbanks area. International Tower Hills, developing its planned new Livengood gold project on the Elliot Highway north of Fairbanks, also plans to purchase power from Golden Valley via a new transmission line that would be built from Fairbanks. The Livengood project is now at an advanced stage of exploration. It would a surface mine with low-grade ore, similar to Fort Knox, except that it is likely to be larger. The company additionally plans to mine placer gold deposits near the planned surface mine. Northwest The Red Dog lead and zinc mine in the western Brooks Range north of Kotzebue is once again the world’s largest zinc producer. Red Dog held that title for many years after its startup in 1989, slipped to second place at one point, but has now reclaimed its title. Zinc and lead concentrates are made at the mine, which is a surface mine, and shipped by road about 60 miles to a port facility on the Chukchi Sea coast. The concentrates are stored through the winter and shipped during the summer, when the Chukchi Sea is ice-free for three months or so. NANA Regional Corp. owns the land at the mine, which is operated by Teck. NANA receives 25 percent of the net profits from the mine as a royalty, which will increase in increments over the years until the corporation is receiving 50 percent of the profits. The land was obtained under the Alaska Native Claims Settlement Act of 1971, so a major percentage of the resource revenues from the mine are shared with other Alaska Native corporations. More than half of the mine workforce are NANA shareholders, many who live in nearby villages. The corporation is also engaged in several joint-ventures to provide support services to the mine, such as in camp operation and maintenance and transportation of the ore by truck. Red Dog was also developed in a partnership with the state, where the Alaska Industrial Development and Export Authority, the state development corporation, financed and owns the road and port facility supporting the mine. Teck pays AIDEA a toll for use of the road and port, and over the years the transportation of ore has been a significant source of income for the state authority. Teck has continued to make improvements at the mine to increase efficiency and moved to a new mine site last year that is adjacent to the first pit that was mine. This will allow mining to continue for two more decades. For the longer term there are other known lead and zinc deposits nearby that can be developed including one a few miles east that another company, Zazu Minerals, is working to develop. The company is also talking with AIDEA on a plan to finance a road to connect with the mine at Red Dog. The region is considered to be a major zinc province and will likely see decades of activity. NANA is also engaged in a new mining venture in the northwest region, in a partnership with NovaCopper, an affiliate company with NovaGold. The companies are working in the Ambler Mining District east of the villages of Ambler and Kobuk, on the upper Kobuk River. The prospect is mainly copper, although there is also gold present. NovaGold, now NovaCopper, has been working for some time exploring the Arctic deposit, a high-grade copper deposit originally discovered by Kennecott Minerals. NANA meanwhile acquired Bornite, a nearby copper discovery also found originally by Kennecott. The two companies have now formed a joint-venture to explore and possibly develop the projects together. The state of Alaska is also working on a planned industrial-type road into the area from the Dalton Highway, which would enhance exploration. Southwest On the middle Kuskokwim River, a partnership of Barrick Gold and NovaGold Resources are in an advanced stage of planning for a large new surface gold mine at Donlin Creek near Crooked Creek village on the Kuskokwim. DonlinGold, the joint-venture company formed to develop and operate the mine, may be applying for development permits this year. The landowners are Calista Corp., the Native regional corporation for the Yukon-Kuskokwim delta, which owns the subsurface rights, and the TKC Corp., a company owned by several villages in the Kuskokwim region, owner of surface lands at the mine. The companies have been working on the project for years and just the exploration work at Donlin Creek has provided significant employment for people in the region, which is one of the most economically depressed parts of Alaska. If the mine is developed it would be a major source of employment in the area. Interestingly, it was geological work by geologists hired by Calista that resulted in the gold discovery. Calista then worked for several years to bring in mining companies to explore and develop the project. No review of mining in Alaska would be complete without mentioning Pebble, a very large copper/gold/molybdenum deposit near Iliamna southwest of Anchorage. The mineral ore body has been explored over several years with both a large, deep resource being located that could be mined with an underground mine, and an adjacent deposit at the surface that would be mined with a surface mine. The developers at Pebble, Anglo American and Northern Dynasty Minerals, have been working on development planning and environmental studies. The Pebble Partnership, the company formed to develop the project, may be applying for permits to build the mine this year after releasing its long-awaited environmental baseline document.

Pebble debate breaks out between BBNC shareholders

JUNEAU — Sharp opinion differences over the proposed Pebble mine within the Bristol Bay community spilled out in Juneau March 19. The occasion was an informal “lunch and learn” noon session for legislators and staff in the state capitol where Bristol Bay Native Corp., the regional Alaska Native corporation for the area, gave a presentation on its activities, finances and dividends paid to shareholders. Jason Metrokin, BBNC’s president and CEO, used the occasion to announce that revenues will cross the $2 billion threshold for its fiscal year ending March 31. That’s up from $1.7 billion last year. Another 2011 milestone is that the corporation will have paid out $100 million in dividends to its shareholders since BBNC was formed in 1972 along with other Alaska Native corporations. The corporations’ share of the original $962 million cash settlement paid by the government was $30 million. Metrokin also wanted to explain BBNC’s reasons for opposing the big Pebble mine project, and that didn’t sit well with a handful of the corporation’s shareholders who were in the audience along with legislators. Metrokin said it is the sheer scale of the Pebble project and a distrust of the state’s permitting process that led BBNC’s board to twice pass resolutions opposing the mine, once in 2009 and again in 2011. However, Lisa Reimers, of Iliamna, a village close to the Pebble prospect, said communities in her part of the Bristol Bay region who stand to benefit from the mine, have no representation on BBNC board and were not a part of that decision. “We have no voice,” she said. Another dissenting voice was Abe Williams, another BBNC shareholder, who said communities in the eastern part of the region support the project being allowed to proceed to the permitting process. He objected to actions that would “short-circuit” the process by preventing the mining companies working on Pebble from filing permits. Williams said it is when the permits are filed that local people will be able to understand how the companies plan to develop the mine, safeguard put in place, and the overall risks and benefits. Metrokin said the corporation understands some shareholders’ opposition to the position taken by the board, but that a survey of shareholders in 2011 showed 81 percent opposed to the mine, an increase compared to 69 percent opposed when a similar survey was taken in 2007. “We have not yet seen the project plan but have seen enough elements of the project that we know there will be risks,” he said. If the project does proceed to permitting, “we’ll be there at every step of the way, to protect the fish.” Of 31 villages within BBNC’s regional boundaries, 26 have expressed opposition to Pebble, Metrokin said. Reimers and Williams said that communities more open to the project are those nearest it and where economic conditions are bad, population is being lost and schools are closing because of the lack of students. Metrokin replied that BBNC supports resource development that is responsible, but Reimers shot back: “You support development as long as it’s not in your back yard?” Not so, Metrokin said. BBNC is working with mining companies on evaluation of prospects on lands in the region owned by the corporation, and the it even owns a small piece of the Greens Creek Mine in Southeast Alaska, a legacy of its prior ownership of Peter Pan Seafoods, which had owned the Greens Creek share. Greens Creek, an underground mine that operates within a protected area on Admiralty Island west of Juneau, is an example of responsible development, Metrokin said. Reimers said this was still a contradiction – supporting some mines but not wanting one particular project to proceed to permitting. Teal Smith, the corporation’s vice president for lands who was with Metrokin, said there is a significant difference between “working with a company to assess what could be possible and what the corporation might support,” or not support. Metrokin said there is a lot of mineral potential in the Bristol Bay region but also a lot of fish, which the corporation wants to protect. “We’ve got to find a balance,” he said. The salmon fishery contributes $500 million a year and 3,500 jobs to the Bristol Bay regional economy and supports regional subsistence, which is valued at an additional $180 million. “We don’t own this resource, but it benefits our region,” he said. Williams agreed that fisheries need protection – he’s a fishermen himself – but pointed out that only 15 percent of the salmon fishing permits in the Bristol Bay fishery are owned by Alaska residents. “We don’t really have much of a voice in this fishery,” he said. Metrokin agreed this is a problem and that ways have to be found to help local people buy back salmon fishing permits held by nonresidents. Williams went on: “I’ve fished for 26 years and I value that resource, but I also believe (over dependence on) fisheries can be our demise,” Williams said. Other options for sustaining the economy should not be blocked by a “pre-emptive” strike to prevent Pebble from applying for permits, he said. Metrokin said BBNC is working to strengthen its regional economy through a board policy to invest 10 percent of its corporate assets within the region and 20 percent of its assets in other parts of Alaska in ventures that support its activities. On Pebble, Metrokin said there is fundamentally a distrust of the state’s permitting process and whether it would really be rigorous. “We worry about this when we hear the governor talking about ‘streamlining’ the permitting process for resources projects,” he said. “Streamlining may not be in the best interest of local people. We want the process to be robust. Our concern is that rural people will not have much of a voice at the table.”  Actions by the state administration and the Legislature last year to allow the state coastal zone program to die has added to concerns felt by people in the region, Metrokin said. Coastal management was a way people in many coastal communities felt they had a role in decisions on permits and other actions on major resource projects that affect coastal areas. A proposition reinstating the coastal management program, brought by citizen initiative will appear on the November election ballot unless the Legislature passes a similar law by its April 15 adjournment, which is unlikely. If Pebble is developed it would almost certainly be an underground mine with possibly an adjacent surface mine. The concern people have in the Bristol Bay region is that any pollution from the mine, such as from tailings stored above ground, could affect surface waters that drain into salmon-bearing streams.

Shops empty as oil production declines

When a film producer called up CH2M Hill’s area manager Tom Maloney a few weeks ago to ask if the company’s empty fabrication shop could be used as space for film production, it was the last straw. Maloney’s job includes keeping the shop full and its people working. “I was tempted – it was revenue – but I just couldn’t let it happen on the odd chance that we might get some work into the shop,” Maloney said. Alaska’s once-bustling oilfield fabrication shops are now empty, CH2M Hill’s among them. ASRC Energy, which also operates a fabrication shop in south Anchorage, reports a similar situation. Last year the welders, pipe fabricators and electrical technicians were busy building things for the oil fields. Not this year. NANA/Colt Engineering operates a facility in the Matanuska-Susitna Borough, and Flowline Inc. does fabrication as well as pipe-coating at its Fairbanks plant. Everyone is in the same boat, Maloney said. “I’ve never seen things so bad. Even in 1988, oil prices dropped to $10 a barrel but we were still busy. That’s because people were optimistic, and planning new projects. They knew the oil price would go back up,” Maloney said. “Now prices are almost $120 a barrel and we’ve got this pessimism. We’re losing our key workers to North Dakota where oil work is booming.” Maloney puts the blame for things on the impasse squarely on the Legislature’s inability to agree on a needed adjustment to the state oil and gas production tax, which he says are too high. That is impeding new investment by oil producers and new projects to keep CH2M Hill’s workers busy. The state House passed a bill last year, House Bill 110, which would lower the taxes, but the Senate disagreed. Senators are now working on their own proposal, but state House leaders and Gov. Sean Parnell are dubious that it will be enough to make a difference. Meanwhile, CH2M Hill’s 100-plus workers normally at work in the fabrication shop aren’t there. These employees, and those who work for the company’s competitors in Anchorage, Kenai and Fairbanks, are indirectly employed by Alaska’s oil industry but many don’t show up counted as oil workers in state labor statistics. “Our people live in Anchorage and Mat-Su and they work here. They don’t go to the Slope,” Maloney said. The last big jobs the fabricators had was two years ago on the building of Eni’s small Nikaitchuq oil field on the slope, and before that it was the construction of the Oooguruk field by Pioneer Natural Resources. Both companies built many of their production facilities in Alaska as “truckable” modules that could be constructed in Anchorage and moved by road to the North Slope. A boom time for the fabricators was from 1998 through 2000 when the Alpine and Northstar oil fields were being developed by ConocoPhillips and BP, and large “sealift” modules, so large they had to be moved to the slope by sealift barge in summer, were built in Anchorage and Nikiski, near Kenai. Since then there have been a steady stream of smaller projects, mostly facilities for expansions of the large oil fields, and then the new fields by Pioneer and Eni. Since then, the work has dried up. When oil companies decide to build their projects in Alaska the decision has a much bigger economic impact than just the module-building, because companies like CH2M Hill are also asked to help install the modules on the Slope, which creates a lot more jobs. “With the Eni project we had 120 in our ‘fab’ shop, working 70 to 80 hours a week, and we had 350 at the site on the slope, on installation. At one time we had as many as 600 working for Eni,” Maloney said. “Now it’s zero.” Engineering work along comes along with a fabrication contract, too, and this creates additional jobs. Terry Bailey, a CH2M Hill vice president responsible for engineer services, recalled that during a particularly busy period when the company was doing the engineering on the CD-3 and CD-4 drill sites for the Alpine field and the DS 1-J drill site in the Kuparuk River field that CH2M Hill had 175 people employed in the design work, and 60- to 70-hour work weeks were the norm. Not all of those people were engineers. Typically 30 percent to 40 percent of those in the engineering group were support people, for example doing data management, Bailey said. Module work always had its peaks and dips, said Nate Andrews, CH2M Hill’s manager for the fabrication plant, but the company has always tried to keep a core group of about 60 skilled and experienced fabrication workers busy, to retain them. With no work in the plant it’s getting really tough to keep these workers, Andrews said. “The problem we now have is that we’re losing our core workers to North Dakota, as well as Alberta. They can work three weeks on and three off, and the employers will fly them back and forth,” Andrews said. If work picks up in Alaska, CH2M Hill will be able to get some of these workers back, but not all. “They can see years of work down there. Why come back here when it’s start-and-stop?” he said. Maloney said these workers, including project managers and supervisors, are critical. “Without people like these you’re not in the construction business,” he said. Andrews said the company is doing everything it can to hang onto these experienced people including putting them temporarily into CH2M Hill’s field maintenance jobs on the North Slope or on loan to the company’s well service group. This isn’t enough to take care of everyone, however, so the company has initiated a “work-load imbalance” program where it has had to furlough workers, but with benefits. There are about 75 people temporarily furloughed for now, who are on call. “Some of these people haven’t worked since last November,” Maloney said. Andrews said it’s tough to compete with North Dakota and Alberta. “We used to be a high-wage state, and the differential allowed us to retain skilled workers. That’s no longer the case. The wages are the same in North Dakota and the hours are much better,” he said. A lot of skilled Alaskans have left the state for better work elsewhere. “I don’t think we’ll get them back,” Andrews said. Hiring new people to fill vacancies, if work picks up, is expensive. “It costs us $7,000 to $12,000 to hire someone from outside the company,” he said. What’s also of concern, however, is that it takes time to a new person to become part of a team and fit in with a company’s safety culture, an area of importance in construction.

Repsol closes exploration well after gas blowout

Repsol E&P USA successfully secured and plugged its Qugruk No. 2 exploration well on the North Slope, the company said March 17. Repsol encountered a shallow gas pocket and experienced a gas blowout at the well on Feb. 15, and although gas stopped flowing Feb. 16 the company has been working to thaw the rig and achieve control of the well since then. There was no fire and no injuries in the incident. Gas was safely vented through a gas diverter system. “Crews have set three cement plugs in the wellbore in accordance with state regulatory standards. The cleanup work on the rig and well pad has been underway for several weeks,” Repsol spokesman Jan Sieving said in a statement. “Cleanup efforts for the area just off the well pad have no begun, managed by Alaska Clean Seas, in conjunction with the Alaska Department of Environmental Conservation.” Alaska Clean Seas is an industry-sponsored oil spill cleanup cooperative for northern Alaska. Repsol reported to the DEC that 42,000 gallons, or 1,000 barrels, of water-based drilling fluids were ejected from the wellbore by the gas kick. As of March 17, Repsol had cleaned and removed 91,939 gallons, or 2,189 barrels, of liquids from the site, mostly thawed drilling fluid and water, the state DEC said in a situation report. In addition, 2,363 cubic yards of solid waste, frozen drilling mud and downhole materials, have been shipped offsite. Repsol is continuing with a second North Slope exploration well at a location southwest of the producing Kuparuk field, Sieving said in an earlier statement. The company does not plan to resume exploration this winter at the Qugruk No. 2 location, he said.

Repsol will abandon damaged Slope well

Repsol USA said it will plug and abandon its Qugruk No. 2 well after drilling crews were unable to repair damage in the well caused by a Feb. 15 gas blowout, a company spokesman said March 14. “We are going to plug and abandon that wellbore,” Repsol spokesman Jan Sieving said in an emailed statement. “Currently we don’t have plans to re-drill at the location. All efforts are currently focused on safely securing and now plugging the well.” The company is finalizing the well control plan for review and approval by the Alaska Oil and Gas Conservation Commission, the Alaska Department of Environmental Conservation said in a separate statement. Sieving said Repsol is working with the state to re-permit two other exploration locations in hopes that those can be tested this winter. The company and its drilling contractor, Nabors Alaska Drilling, had cleaned frozen drill mud from the rig and restored operations but had encountered blockages in the well after attempting to circulate drilling fluid to regain control. A coil-tubing unit was used to clear the obstructions. The drilling and well control crew attempted to then move the pipe to reestablish mud circulation, but the attempt failed. “The attempt failed and they were unable to circulate fluid through the well,” the DEC said in its statement. Repsol has not yet indicated whether it will attempt to drill a new well at the prospect or move the rig to another location. Meanwhile, the company reported earlier that it has resumed drilling at a second prospect, the Kachemach-1 exploration well, after that operation was suspended to assist with the Qugruk No. 2 incident. Repsol encountered a shallow gas pocket while drilling at Qugruk No. 2, at 2,563 feet, just below the permafrost layer. A gas “kick” resulted in drilling fluids being ejected from the well and a release of gas that was dispersed through a diverter. The rig was evacuated and shut down. At the time the drilling contractor had not yet installed surface casing in the well, so the blow-out preventer had not yet been installed, according to Cathy Foerster, a commissioner on the Alaska Oil and Gas Conservation Commission. The Qugruk No. 2 well is in the Colville River delta north of the Alpine field, which is producing. The Kachemach-1 exploration well is southwest of the producing Kuparuk River field on the slope.

State identifies challenges with oil shale plays

State agencies have identified some key technology and permitting challenges for a North Slope shale oil play, an official in the state Division of Oil and Gas says. Alaska-based independent Great Bear Petroleum and Halliburton are working in a partnership to test the production potential of a large shale formation south of the producing Prudhoe Bay and Kuparuk Ruver fields, with the first two test wells planned this spring, said Greg Hobbs, a petroleum engineer in the state Division of Oil and Gas. Great Bear acquired 500,000 acres of state leases in the shale area in a 2010 lease sale and negotiated its deal with Halliburton in 2011. Separately, San Diego-based Royale Energy Inc. acquired 100,480 acres in the shale areas in a December 2011 state lease sale. If it happens, a North Slope shale play could potentially affect an area as large as the Prudhoe Bay and Kuparuk River fields 30 miles to the north. Hobbs is leading a state team assessing problems with securing state and federal permits for such a large undertaking, which would have substantial effects on surface lands. “We believe a North Slope shale play would be very similar to the Eagleford shale development now happening in Texas,” in terms of the scale of surface facilities and resource potential, Hobbs said. High costs on the North Slope could be a barrier. Also, a shale oil development on the Slope would be done substantially different than those in the Bakken in North Dakota and Eagleford. There are three shale formations in the area that are known to be the source rocks for the large conventional fields a few miles north, the most important being the Shublik shale, the source of oil for the conventional Prudhoe Bay field, he said. State geologists have little doubt oil is in the shale and that it is of good quality, but a key technical question is whether the shales are brittle enough to be fractured so the oil will flow, Hobbs said. Once that is answered in the tests to be drilled this spring, the second concern is for a source of water to make fracturing fluid, he said. Unlike in the Eagleford and Bakken, there is no practical source of surface water on the North Slope for fluids needed for large-scale hydraulic fracturing operations. The state team assumed that 1 million to 4 million gallons of water will be needed for each horizontal shale oil well, based on data from the Eagleford, Hobbs said. In conventional drilling on the Slope, tundra lakes, even when frozen, are tapped for water, but doing this on a scale needed for shale oil drilling would be major issues for federal and state environmental agencies. “The state is very concerned about any use of fresh water,” Hobbs said. A solution could be tapping underground reservoir water if it exists in the area. This could be present if the water-bearing part of the large Ivishak formation from Prudhoe Bay extends that far south, which geologists believe. Still, the availability of the water must be confirmed by drilling, Hobbs said. However that water would be brackish, and shale oil operators in the Lower 48 have typically used fresh water. The state believes the effectiveness of brackish water for use in fracturing is an uncertain, although both Great Bear and Halliburton have said they believe it can be used, Hobbs said. The are a host of other technical questions such as what types of down-hole pumps can function in highly-deviated wells drilled on multi-well pads. Pumping jacks, the well-known lift mechanisms typically seen in low-producing Lower 48 oil wells, would be impractical on the North Slope because of weather and the deviated, high-angle wells. Semi-submersible pumps could be used but they do not accommodate easily to the declines in production commonly seen with shale oil wells, at least at first, Hobbs said. A key difference with Lower 48 shale plays is that North Slope conditions will require multi-well pads instead of single-well pads that are common in the Bakken and Eagleford. A scenario developed by the state, to assess permitting difficulties, assumes each pad covering about four acres with 12 wells per pad and each well with two below-ground horizontal production legs about 10,000 feet in length. In its planning, the state is assuming four miles between each producing pad, with gravel roads connecting the pads. The gravel requirements for pads and roads would be substantial, Hobbs said, with 105,000 cubic yards of gravel needed for each pad and about 54,000 cubic yards needed for each mile of road. The development scenario assumes an operator using 12 rigs and drilling about 200 wells per year, and working over a 10-year period. Development could begin where Great Bear and Halliburton are planning the initial test wells on gravel pads adjacent to at the existing Dalton Highway, and extending east or west. The initial shale play area could extend across an area of 50 miles east and west and about 19 miles north-south, Hobbs said, although the shale formations are believed to extend far to the west into the National Petroleum Reserve-Alaska.

Senate on a slow track with work on state oil tax changes

With less than four weeks left in the 2012 legislative session, state senators are on the slow track in their work on changes to the state’s oil production tax. The Senate Finance Committee took up Senate Bill 192 on March 13, a bill passed out of the Resources Committee on March 2. Sen. Bert Stedman, R-Sitka, co-chair of the finance committee, said the panel will continue working on the bill through to the end of the week of March 19. “A lot of the major areas to be dealt with are in the bill (passed from the Resources committee) but there’s still a lot of work to be done,” Stedman said in a briefing by Senate leaders. If the finance committee moves the bill out, for example on March 23 or March 26, and the Senate passes the SB 192 promptly, the state House would have less than three weeks to consider the senate’s proposal. The House passed its version of oil tax reform last year, in House Bill 110. The Senate bill, as it is shaping up, is much different than the measure passed by the House. Senate President Gary Stevens, R-Kodiak, had hoped to have the Senate’s bill to the House by mid-March, but he is supporting his colleagues taking their time. “This is a process we have to go through, and we have to be cautious and understand every change we make. It’s important that we do it right,” Stevens said. Even with three weeks there would still be time for the House to deal with the bill, he said. “The House is watching what we’re doing. I believe there will be enough time.” On the House side, however, Rep. Bill Thomas, R-Haines, who co-chairs the House Finance Committee, is leery of the Senate oil tax bill being piled onto “50 bills stacked up in our committee, plus the capital budget,” he said. If it happens, it means some things just won’t get done before the required April 15 adjournment. The deadline, on the 90th day of the session, is set in state statue, and there are provisions for an extension if needed. Legislators, or the governor, can also call a special session to deal with a specific topic, such as resolving differences over the oil tax. The version of SB 192 passed from the Senate Resources Committee makes an adjustment in the “progressivity” formula of the production tax, a formula that escalates the rate of the tax as crude oil prices climb. In the current law the tax rate increases at a rate of 0.4 percent for every $1 increase in a producer’s per-barrel net profit above $30 per barrel, with a cap in the tax so that the state tax will not exceed 75 percent of a producer’s profit. The bill pending in the Senate Finance Committee would reduce the rate of increase to 0.35 percent, and also lower the cap to 60 percent of net profits. Alaska’s production tax is a net profits-type tax that starts at a base rate of 25 percent of net profits and increasing according to the progressivity formula. As it now is written, SB 192 makes other changes including lower rates of tax for “new oil” developed by a producer above the existing production, a so-called minimum tax based on gross revenues, intended to protect the state if oil prices fall, and a “decoupling” of the state tax on oil and natural gas. The two are now joined so that both are taxed on the basis of the combined energy value, which was done because much of the gas on the Slope would be produced at Prudhoe Bay, an oil field. Since gas and oil would be produced in the same wells, the costs of production would have to be apportioned in the net profit tax calculation. Taxing the combined energy value would make this administratively easier. However, because the two have sharply differing values — oil now has a market price that is high and gas is at record lows — the combined method of taxation could result in substantial losses of oil revenues once commercial production of gas begins. On other matters, the state House is continuing its work on House Bill 9, which would give the state’s Alaska Gasline Development Corp. more flexibility in pursuing a 24-inch gas pipeline built from the North Slope or joining in a partnership with private companies to build a bigger project. The House Finance Committee held hearings on the bill March 13. Earlier versions of the bill raised concerns over a proposal to require municipal governments to supply free sand and gravel to a pipeline built or controlled by ADGC. Current versions of the bill would have the state corporation pay the prevailing rates for sand and gravel to municipalities. There were also concerns raised over provisions in HB 9 which limit the authority of the Regulatory Commission of Alaska over the project, and which exempt the project from state and local property taxes. Changes are being worked to the regulatory provisions but the tax exemption, which would last only during the construction phase, is still in the bill. The ADGC’s 24-inch pipeline is in an engineering and planning stage with a Draft Federal Environmental Impact Statement out for public comment. It is intended as a backup plan to bring North Slope gas south to Alaska communities in case a proposed large 48-inch pipeline project is not built. If the large pipeline is built the ADGC project could become a “spur” pipeline, bringing gas from the large pipeline to Southcentral Alaska.

Buccaneer Energy says its new Kenai gas well will produce

Buccaneer Energy’s new Kenai Loop No. 1 gas well near the city of Kenai is performing, producing about 5 million cubic feet of gas per day after about two weeks of steady production, the company says. Production began Jan. 14, and the gas is being sold to both Enstar Natural Gas Co. and ConocoPhillips Alaska Inc. under contracts Buccaneer has signed with both companies. “Based on the available information the company is confident that the (Kenai Loop No. 1) well can be produced at higher rates,” Buccaneer spokesman Dean Gallegos said. “The current production rate will be maintained and monitored over the next 30 to 60 days and, if appropriate at that time, a decision will be made to increase production rates.” Buccaneer’s discovery of gas at a location one mile from the long-producing Cannery Loop gas field on the Kenai Peninsula is being cited widely as proof that substantial amounts of gas are yet to be discovered in the Cook Inlet basin. The company’s contract with Enstar allows the company to sell Enstar a minimum of 5 million cubic feet per day and a maximum of 15 million cubic feet per day as soon as a gas storage facility being constructed in the area is ready to accept gas, the statement said. Enstar will pay an annual average price of $6.24 per thousand cubic feet. Cook Inlet Natural Gas Storage Alaska LLC, which is developing the underground gas storage facility, has informed Buccaneer that it expects to be ready to accept gas for injection in early April. In the meantime, Buccaneer has been offering gas to the utility under Enstar’s daily auction system. The company is also supplying gas to ConocoPhillips, which has contracts to supply Chugach Electric Association, and owns and operates the Kenai natural gas liquefaction (LNG) plant. That facility is now in a suspended state but the making of LNG from gas will resume in April or May in anticipation of LNG cargo shipments to customers in Asia in the last half of 2012, ConocoPhillips spokeswoman Natalie Lowman said. Four shipments are being planned for now, she said. Meanwhile, Buccaneer has a 25-square-mile three-dimensional geophysical survey is under way in the immediate area to determine the best locations for future wells. “With improved seismic imaging the company believes it will be possible to rapidly drill and place on line a number of wells from existing drilling pad sites,” Gallegos said. Buccaneer is in the process of contracting for a drilling rig for the next well, with drilling expected to begin in April or May, he said.

Repsol's effort with Slope well delayed by blockage

Repsol E&P USA has encountered a new problem, a blockage in the well bore of its Qugruk No. 2 exploration well on the North Slope, which has delayed attempts to bring the well under control. Repsol encountered a shallow gas pocket Feb. 15, which resulted in a gas blowout and evacuation of the rig. The well is on the Colville River delta, west of the producing Prudhoe Bay and Kuparuk River fields. In a situation report issued March 3, the Alaska Department of Environmental Conservation and drilling contractor Nabors Alaska Drilling was using a special tool to survey the well for damage and discovered a blockage of some type in the well pipe. “A coiled tubing unit and crane have been contracted to clean out the drill pipe but the temperature must be above minus 35 degrees F. for them to operate,” the agency said in a statement. Ambient temperatures at the well were at minus 44 degrees F. with a wind chill of minus 68 degrees over the weekend. The weather forecast is for a gradual warming  and for temperatures to reach above minus 35 degrees by March 6, the agency said. Once the coiled-tubing unit is on location and the well is cleaned out, a second wireline log will be run to assess the condition of the well pipe and a well-kill plan will be finalized, the ADEC statement said. The flow of gas from the well ended the evening of Feb. 16, about 40 hours after the blowout was experienced, with an estimated 42,000 gallons, or 1,000 barrels, of water-based drilling fluids ejected from the wellbore. No injuries resulted but the evacuation of the rig. The freezing of drill fluid on the rig, the possibility that some methane may be seeping from the open well, plus extreme cold temperatures have slowed  the recovery operation. Cleaning and drying of the rig’s power components have been completed, however, and the rig is operational. The well will be considered back under control when the drilling crew is able to pump drill fluids down the pipe, according to Cathy Foerster, Commissioner on the Alaska Oil and Gas Conservation Commission.

Hospitals doing OK, need help recruiting

Given the distances, high costs and problems in workforce recruitment, Alaska’s hospitals feel they’re doing OK in serving health care needs in the state. National medical-care review groups seem to agree. Health Strong Index ranked two of the state’s smaller hospitals, South Peninsula Hospital in Homer and Ketchikan General Hospital, among the top 100 U.S. “critical access” hospitals. Critical access is a special federal designation for small community hospitals that offer 24-hour emergency services. Larger hospitals are getting some kudos, too. U.S. News & World Report recognized Alaska Regional Hospital in Anchorage as one of the nation’s best regional hospitals. Doing OK despite some problems is one message the hospitals conveyed to state legislators in briefings in Juneau Feb. 29 and March 1. A second was that some targeted state help is needed in a critical area: workforce recruitment. There is a need to attract more physicians and medical technicians in certain fields to Alaska, and there is a critical need to train more resident nurses who can assist in operating rooms to reduce the high cost of bringing in these specialized nurses from out-of-state. It’s a serious issue. “Some operating rooms have about 50 percent travelers,” or specialty nurses brought in from Outside, said Karen Perdue, executive director of the Alaska State Hospital and Nursing Home Association, or ASHNHA, which organized the briefings for lawmakers. The association is pushing for legislation that would help new physicians and technicians repay education loans if they agree to come to Alaska to practice, particularly in small communities. House Bill 78 is now pending in the House Finance Committee. As for the operating room nurses, the hospitals are also asking the Legislature for $85,000 to help finance curriculum design and instructional materials for the “perioperative” nurse training, which six hospitals already have under way with 15 student nurses in training. Included in this is $25,000 for travel and lodging for student nurses from rural hospitals, legislators were told. “Rural hospitals have limited staff and tight bottom lines. Still, they must be expected to bear the cost of paying the employee in training and lodging and travel expenses,” said Purdue. Workforce recruitment is a bump in the road, though a big one, but the hospitals said things are going very well in another recruitment and training area, for registered nurses. A University of Alaska Anchorage program that was started to train resident registered nurses a decade ago has been a resounding success and has met hospitals’ needs for entry-level nurses, Mike Powers, general manager of Fairbanks Memorial Hospital, told the Senate Health and Social Services Committee in the Jan. 29 briefing. “We’re getting exactly the right number of newly graduated nurses we need. Thanks to the university, we’re holding our own,” Powers said. The university has a two-year registered nurse program offered at 16 campuses around the state and a four-year program that grants a bachelor of science degree in nursing. Just getting a new nurse isn’t enough, though. “We have to remember that having a new nurse on the floor, with a degree, doesn’t mean she or he is ready to take over the full patient load. These people need mentoring,” Powers said. Annie Holt, CEO of Alaska Regional and a registered nurse herself, appeared with Powers in the Senate committee briefing and said the challenge for hospitals now is having enough experienced nurses to serve as instructors for new recruits because older nurses are retiring. Alaska is also doing well in another area that has plagued physicians and medical providers: malpractice liability. “Malpractice insurance and liability is still a problem but much less so than before the Legislature passed a tort reform law several years ago. Because of that, Alaska is considered a favorable environment for practitioners. It’s actually a good recruiting tool,” said Pat Branco, general manager of Ketchikan General Hospital, a city-owned hospital. Medicare concerns Low Medicare reimbursement for senior citizen care is a continuing problem, but hospitals are generally paid at higher rates than Medicare pays physicians. Also, the federal government pays the full costs of care for seniors in small community hospitals designated as critical access by the federal government, according to Perdue. There is some concern that the federal government may change this, which will have to be watched, Perdue said. Overall, because Alaska’s population is still relatively young, Medicare patients are not as large a part of a hospital’s business compared to the Lower 48, Powers said. “Medicare is only 35 percent of our business, but in Phoenix it is 70 percent to 90 percent of some hospitals’ business,” he said. The goal of most hospitals is to break even on Medicare, but this isn’t possible in Alaska, where costs are higher. “If the costs aren’t recouped, they are shifted to commercial payers, who are about 50 percent of our business,” Powers said. Branco, of Ketchikan General, said Medicare payments are not uniform in the Lower 48 and there can be  lot of variation between one part of the nation and another. In Alaska, access to primary care for senior citizens, particularly physicians and particularly in Anchorage, has been a serious problem. Powers said that Fairbanks Memorial’s affiliation with the multi-specialty Tanana Valley Clinic has opened up more services for Medicare patients, easing the problem in the Fairbanks area.  In Anchorage, an affiliation between Alaska Regional and the nonprofit Alaska Medicare Clinic has helped boost the patient load at that clinic, helping secure its financial viability. Alaska Medicare Clinic opened last year to address the shortage of primary care for seniors. It serves Medicare patients in the Anchorage area as does Anchorage Neighborhood Health Clinic, another nonprofit. Providence Alaska Medical Center also sends patients to Alaska Medicare Clinic and operates its own service for seniors, Perdue said. ‘Cherry picking’ competition Meanwhile, competition from “niche” health providers is a continuing problem for hospitals, Powers said. Competitors, usually groups of physicians or a private company, would open an out-patient clinic in competition with the services offered by the community hospital. “They take the specialty services that are the most profitable, arguing they can perform them faster and cheaper. It’s an ongoing debate,” Powers said. The issue is that by “cherry picking” the profitable specialties, the competitors leave the community hospital with the less-profitable services. Since hospitals are required to remain open for emergency service and to take all-comers regardless of ability to pay, this can undercut the viability of a local hospital. Central Peninsula Hospital in Soldotna is currently engaged in a battle with competitors who plan competing surgery centers. The state Department of Health and Social Services licenses new medical facilities above a certain size and has yet to make a decision in the area’s competition. Another trend in health care that is manifesting itself in Alaska is increasing “alignment” between local physicians and hospitals, which in some cases takes the form of the physicians simply becoming employees at the hospital. Branco said all physicians in Ketchikan are now employed in the hospital, having dropped their independent practices because of low reimbursements and the small size of the community. Fairbanks Memorial is now affiliated with Tanana Valley Clinic, which has a group of 45 physicians offering out-patient services. This is causing some tensions with physicians who are not aligned, Powers said, and the hospitals have to be sensitive to that. “These changes are happening because both physicians and hospitals are requesting it to prepare for a more integrated health care future,” Perdue said. Economies of health Meanwhile, hospitals make a big economic contribution in the communities they operate in. Branco said Ketchikan General has a $28 million local payroll but when employees of various service and support companies are added, and the multiplier effects are included, the total direct and indirect payroll effect is $100 million, which is huge for a small community like Ketchikan, he said. Like all hospitals , Ketchikan has its share of uncompensated care, or services not paid or fully paid. That came to $6.5 million last year, Branco said. Holt, Alaska Regional’s CEO, said her hospital, one of three major facilities in Anchorage, employs 823 people with a $53 million annual payroll and an additional $13 million in benefits. The hospital is privately owned and pays municipal and state taxes. Alaska Regional paid $3 million in local and state taxes last year, Holt said. Small community hospitals have special challenges. Recruitment of physicians and key technical staff is a problem for all hospitals in the state, but Branco has learned he has to be brutally up-front with potential recruits to Ketchikan. “Ketchikan is a beautiful place, but we have to tell them about the rain. It rains a lot,” he told the legislators. It wasn’t believed at first, which resulted in Ketchikan General having a 30 percent turnover among new physicians, a huge cost item. “We decided we had to really tell them about the rain,” Branco told the legislators. The new policy, to be bluntly frank, has paid off. More new recruits who come to Ketchikan stay, he said. Logistics is another challenge for small community hospitals, Branco said. Oxygen, for example, must be shipped in to Ketchikan by barge from Seattle. Once, when there was a disruption in barge service, “we were within hours of running out of medical oxygen,” Branco said. The biggest challenge all hospitals face, however, is to keep up with rapidly advancing, and increasingly expensive, technology and to able to offer as many services as possible in relatively small population areas, even in Alaska’s largest cities. “The challenge we face is that we are offering advanced services like cancer and cardiac care, and the concern is how robust these services can be in a community of 100,000 people,” Powers said. This will get even more complicated as the graying of Alaska’s population continues. Seniors tend to seek more medical care and they prefer to have it available locally. Alaska’s senior population was estimated at about 55,000 in 2010. If current trends continue it will be about 92,000 by 2010.

BP finishes first test production well drilled to Sag River

BP has completed the first of five pilot wells drilled to test production from the Sag River formation that overlies the main producing reservoir of the Prudhoe Bay field, company officials told state legislators Feb. 23. The test wells involve long, extended horizontal production wells, drilled from the surface at an angle and then turned horizontally to intercept the thin production layer of rocks. The first well was drilled with a 6,700-foot horizontal production section through a thin layer of oil-bearing reservoir about 20 feet thick, Damian Bilbao, BP’s Alaska resources and development director told the Senate Resources Committee. If the wells are as productive as hoped, BP could develop 200 or more production wells in the Sag River over a 10-year period, adding 150 million to 220 million barrels of new reserves to the Prudhoe Bay field, Bilbao said. The investment required would be $270 million to $610 million. BP is also considering testing the Sag River formation in the nearby Milne Point field, which could add 10 million to 50 million barrels of oil. In other developments, Claire Fitzpatrick, BP’s chief financial officer, said the company is continuing work on a pilot heavy oil production project at the Milne Point field. However, even if technical problems are worked out and BP is able to produce oil from the large Ugnu oil deposit, economically it would be at least 10 years before any significant amount of oil, such as in the range of 10,000 barrels per day, is produced, Fitzpatrick told the senators. BP’s first heavy oil production test at Milne Point was encouraging, with a horizontal well producing about 650 barrels per day over a 100-day period, state Oil and Gas Director Bill Barron said in a presentation to the committee earlier in the day. Barron said BP is now searching for a specialized rig to drill more of the heavy oil test wells. These would employ the CHOPS technology (Cold Heavy Oil Production with Sand) that is used in Alberta and that BP will adapt to the North Slope. The first heavy oil test well was drilled using a more conventional horizontal production well in the Ugnu, and it worked better than BP expected. This well is now off production so that BP can modify pumps used in the process. Ugnu heavy oil has a quality that ranges from 10 to 15 degrees API and is technically challenging. In comparison, conventional crude oil in the Prudhoe Bay field has an API gravity of 29 degrees API. However, there is a large resource, an estimated 23 billion barrels of oil, in the deposit, which is shallow and overlays the deeper, conventional fields in Prudhoe Bay, Milne Point and Kuparuk River. While only a part of the resource will ever be produced, even a 10 percent to 15 percent recovery would be a large amount of oil. One other challenge with heavy oil is that it cannot flow by itself through the Trans Alaska Pipeline System. It must be mixed with conventional light crude oil so that the combined liquids will flow. On other matters, Fitzpatrick said a record number of Prudhoe Bay production facility “turnarounds,” or major maintenance projects this summer. This will mean a drop of production and oil moving through the Trans-Alaska Pipeline System this summer. Fitzpatrick said BP will also expand, and in fact will double the application of a proprietary Enhanced Oil Recovery technology the company has developed. The Bright Star EOR process involves injection of polymers to improve the effectiveness of oil recovery in waterflood. Another proprietary EOR process, called Low-Sal also will be tested at Prudhoe Bay this year by BP. Low-Sal involves the use of low-salinity or even fresh water in a waterflood instead of the briny formation water or even seawater currently used. Low-Sal has been tested by BP at the nearby Endicott field in past years and has been found to be effective in improving oil recovery. Fitzpatrick said BP also plans a large summer offshore seismic program in the Simpson Lagoon area north of the Milne Point field. Substantial sections of the Milne Point field extend out under the ocean and are produced with extended-reach production wells drilled from shore. The seismic will identify opportunities for fill-in drilling, she said. Other plans at Milne Point, which will depend on results of the summer seismic program, include additional in-fill drilling and pad expansions that could add 25 million to 35 million barrels of reserves.

USGS estimates on Slope shale oil, gas puts Alaska near top

The U.S. Geological Survey has estimated the potential of undiscovered, technically recoverable onshore shale oil and gas resources on the North Slope, with estimates ranging from zero to 2 billion barrels of oil and from zero to 80 trillion cubic feet of gas. The starting point is zero because shale oil and gas have not actually been produced on the Slope and it is not known whether hydrocarbons can actually be produced, much less whether the production can be profitable. The estimate has placed the North Slope as in second place in shale oil potential among known U.S. shale resource areas, behind only the Bakken Shale of North Dakota and ahead of the Eagleford shale of Texas, USGS research geologist Dave Houseknecht said in a Feb. 23 briefing. In terms of shale gas potential the North Slope ranks fourth in the nation behind the Marcellus shale of Pennsylvania being No. 1, Houseknecht said. State of Alaska officials were surprised at the modest estimate given the massive size of the known shale formations in northern Alaska. Bob Swenson, the state geologist and director of the state Division of Geological and Geophysical Survey, said he believes the USGS assessment is conservative because only three shale source rocks are considered. There may be other shale source rocks for hydrocarbons on the North Slope that are undiscovered. “We were not so surprised at the shale oil number, but we were surprised at the shale gas number, because we know the entire National Petroleum Reserve-Alaska is very gas prone,” Swenson said. “We’re going to be taking a close look at the USGS study and particularly the assumptions that were used. They are good scientists, but it’s all about the assumptions you make. This just illustrates how little we know about the North Slope, because for a basin as large as this there are still relatively few penetrations,” through exploration drilling, Swenson said. Shales like those found on the North Slope are known as “source” rocks – those formations from which hydrocarbons, such as oil and gas, originate, the USGS said in a statement. Conventional oil and gas resources gradually migrate away from the source rock into reservoir formations from which they can be produced, whereas continuous resources, such as shale oil and shale gas, remain trapped within the original source rock, the USGS said. Swenson said he and other state geologists believe that while oil has seeped from the shales to form the large conventional fields on the Slope, there is still a great deal remaining. However, there are critical questions that must be answered, such as how much of the original oil is still in place and whether the shale rock itself lends itself to “fracturing,” a process that allows the oil and gas to flow through the very tight shale rock. In a briefing, Houseknecht said the USGS estimate also mapped out the “sweet spot” of shale oil resources as being in an area reaching about 50 miles south of the Beaufort Sea coast, an area where Great Bear Petroleum, an independent company, has obtained leases and is planning two test wells later this spring. The assessment also found that the shale rock formations studied do not exist in the 1002 area of the northern Arctic National Wildlife Refuge, and that they also “pinch out,” or end, in the northeast National Petroleum Reserve-Alaska and do not extend as far as Point Barrow. The estimate considered technically recoverable oil and gas resources, which are those quantities of oil and gas producible using currently available technology and industry practices, regardless of economic or accessibility considerations, the USGS said in a press release. Three source rocks of the Alaska North Slope were assessed in this study: the Triassic Shublik Formation, the lower part of the Jurassic-Lower Cretaceous Kingak Shale, and the Cretaceous pebble shale Hue Shale. These shale formations are known to have generated oil and gas that migrated into conventional accumulations, including the giant Prudhoe Bay field. However, these shales also likely retain oil and gas that did not migrate out. Shale oil is oil that was generated naturally in source rocks but that never migrated out of them. It should not be confused with “oil shale,” a source rock in which oil has not yet been generated, but that is capable of generating oil if artificially heated, the USGS statement said. There is a large range of uncertainty associated with these assessment numbers because of the questions associated with estimation of undiscovered, continuous resources in source rocks from which no attempt has been made to produce oil or gas. However, the recent success of shale oil and shale gas development in the Lower 48 demonstrates the technical viability of such resources. Therefore, this new assessment provides an estimate of potential resources that may be technically viable in this frontier region, the USGS said. “Providing scientifically sound, publicly available assessments of the quantity of new, untapped oil and gas resources in frontier areas is but the first step in weighing their potential contributions to energy supplies as well as the impacts of recovering them,” said USGS Director Marcia McNutt in the briefing.

Shell files "pre-emptive strike," seeks approval of process on spill plan

In what the company described as a “pre-emptive strike,” Shell asked an Alaska federal court for a declaratory judgment on the Department of the Interior’s approval of the company’s Chukchi Sea oil spill response plan, a company spokesman said Thursday. “We’re not asking for the court to approve the plan but the government’s process in approving it,” company spokesman Curtis Smith said. “We believe any challenge to the approval will be on process, not the merits of the spill plan.” The move is unusual. Smith described it as a kind of “pre-emptive” strike – but it is intended to get the issue before the court now rather than waiting for environmental groups to file actions in early summer, just as Shell is moving its drill fleet into place, Smith said. Shell hopes to drill in both the Chukchi Sea and Beaufort Sea.  “We’ve already heard from environmental groups that we’re trying to stifle their freedom of action, but we’re inviting anyone and everyone to get into this. We just want to talk about this now rather than waiting,” he said. The case was filed Feb. 29 in the U.S. District Court in Anchorage. It has not yet been assigned to a judge, and it is unknown whether the court will actually hear the request, Smith said. Meanwhile, legal challenges by environmental groups over the approvals of exploration plans for both drilling areas and an approved air quality permit are pending in the 9th Circuit Court of Appeals, Smith said. Shell has been notified that the appeals court will hold a hearing in the first week of April, he said. As for the Feb. 29 filing in Anchorage, “We’re not sure this has ever been done before, but we felt we owe it to our shareholders and our Alaska stakeholders to give this a shot,” Smith said. Mobilizing a small fleet of vessels for Shell’s Arctic drilling will cost the company “well beyond $400 million,” Smith said, and Shell has already spent about $4 billion in its efforts to explore the Alaskan Arctic offshore. About half of that was paid to the federal government for leases in the 2008 Chukchi Sea OCS lease sale in which Shell, ConocoPhillips, Statoil and Repsol acquired leases. Smith said Shell is on schedule in mobilization of its fleet, which will include two drilling vessels and a variety of support ships including a tanker, a spill response vessel and ice-class anchor-handling vessels. The Noble Discoverer drillship is now en route to Seattle from New Zealand after a brief delay when the ship was boarded by Greenpeace activists, Smith said. The second drill vessel, the Kulluk, is now in Seattle undergoing a retrofit of its engines and exhaust emissions system. The spill response vessel will come to Alaska in April to conduct training sessions in Valdez, while the rest of the fleet will be underway in late spring or early summer. Shell is already studying long-range ice forecasts for the Chukchi and Beaufort Seas and decisions on which area will be drilled first will depend on conditions in mid-summer, Smith said.

Repsol works to thaw rig after gas blowout

Repsol E&P USA was working Feb. 22 to get its drill rig operational and the company’s Qugruk 2 exploration well in the Colville River delta on the North Slope back under control after a shallow gas blowout, officials with the Alaska Oil and Gas Conservation Commission said. The company Feb. 15 experienced a gas “kick” and gas release at the well, and the rig was evacuated. The flow of gas ceased late the following day, Thursday, and since then Repsol and its drilling contractor, Nabors Alaska Drilling Co., have worked to assess the rig condition and get equipment thawed and operational, according to Jim Regg, senior inspector with the Alaska Oil and Gas Conservation Commission. Repsol and Nabors had not yet installed a blowout preventer on the well because the “surface casing,” the uppermost section of the well equipment, had not yet been set and cemented, Regg said. After the surface casing is installed the blowout preventer is installed. Meanwhile, a gas “diverter” is put in place on the rig so that if gas is encountered at a shallow level, which happened in this case, the gas can be safely diverted. Thawing operations started Feb. 20, Regg said. “They started thawing equipment yesterday and it’s going to take them some time to get this done. They are being very meticulous about this, and very mindful of safety,” Regg said. Some equipment on the rig may have to be repaired, he said. No injuries or fire resulted from the incident. Drilling mud was blown from the well, however. Repsol reported that about 42,000 gallons of water-based drill fluid, or 1,000 barrels, were spilled from the well. The well cannot be considered under control until the rig is operational, however. Houston-based Wild Well Control Inc. is working with Nabors and Repsol. In a situation report released Feb. 20, the state Department of Environmental Conservation said, “Well control workers have set up boilers outside the rig and begun using steam to thaw frozen drilling mud and water from around the drill cellar access doors. Thawing operations will first focus on gaining access to hydraulic lines and other equipment in the drill cellar that are essential to operating the well. “Frozen material in the drill cellar is several feet thick, and at this time crews are not able to estimate how long it will take to complete the necessary thawing operations,” the DEC said in the report. Meanwhile, cleanup operations near the rig have begun. “Nabors Drilling and Cruz Construction Inc. workers have removed approximately 200 cubic yards of drilling mud and contaminated snow from areas adjacent to the east, north, and west sides of the drilling rig. This will improve access for crews and equipment working to cleanup and repair the rig,” DEC said in its situation report. “Due to the potential danger posed by the gas diverter in the event the well resumes flow, no cleanup will take place on or off the pad to the south of the rig before well control work is complete.” Regg said that currently, there is no gas being released form the well, but that the gas diverter is still in place. Gas blowouts from shallow gas pockets have occurred previously on the North Slope. Methane hydrates are known to exist in the area and are believed to have contributed to previous shallow gas blowouts. Cathy Foerster, a commissioner with the AOGCC, said the agency will investigate circumstances of the blowout after the situation has normalized. One area of inquiry will focus on why a shallow hazard survey, which is done prior to the start of drilling of an exploration well, did not show the presence of the gas pocket, Foerster said.


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